Water injection operations for flooding (to sweep oil to the producer), for pressure support (to fill the voidage left by the produced fluids), and/or for disposal are becoming a key element in modem oil-fields operations and the like. For flooding and pressure support applications, water from at least three possible sources can be used in injection operations. These sources are seawater, produced water, and saline aquifers water. FIG. 1 depicts possible schemes for water injection operations using such sources of waters. Table 1 presents examples of the three possible sources of waters for injection operations.
Seawater injection is the most common option, particularly in offshore and near coastal oil-gas fields operations. This is attributed to its abundance and acceptable compatibility with the salinity of most reservoirs formation waters. Seawater contains traces of suspended matters, bacteria, oxygen, alkaline scale, and more importantly appreciable concentrations of sulfate. Thus, seawater requires extensive pretreatment using standard processing equipment (coagulation with poly-electrolytes, multimedia filtration, disinfection with hypo-chlorite or biocide or ozone, oxygen removal, and in some cases acid treatment). Such a pretreatment, however, excludes the selective removal of sulfate.
As used herein and in the claims, the term “seawater” includes both ocean water and seawater and the term “sea” includes both seas and oceans.
Re-injection of produced waters is another option. As environmental regulations continue to evolve, the reuse, rather than the discharge of produced waters to surrounding environment, becomes an attractive option for injection operations. This option is favored in reservoirs where water injection is being considered for pressure support, particularly when the amounts of produced waters are in the range of 50% or more of the total fluids produced (mature oil-gas fields). However, re-injection of produced water alone can not provide reservoir voidage replacement especially when watercuts are relatively low. In such cases, produced waters must be supplemented with seawater or aquifers water. Moreover, the loss of reactive gases will change the composition and pH of the produced waters, and thus creating a potential compatibility problem when produced waters are re-injected. Furthermore, re-injection of produced waters could reduce injectivity due to its oil content, particle content, and temperature.
The third possible option is to employ saline waters from nearby aquifers (e.g., onshore subsurface brine waters aquifers or below seabed offshore brine waters aquifers) that are not related to oil-gas fields produced waters. Aquifers waters are biologically clean and depleted of oxygen. Temperatures of subsurface waters are in most cases almost close to temperatures of surface waters. Thus, they do not require extensive pretreatment as the cases with seawater and produced waters. However, some of such waters contain gases (e.g., carbon dioxide, hydrogen sulfide, methane, etc.) which would necessitate a gas removal facility. Furthermore, aquifers waters are in most cases insufficient as a stand alone source of waters, and thus can be supplemented with either produced waters or seawater to provide the needed amounts for injection operations.
The availability of waters in a sufficient quantity when and where needed, and with adequate quality (e.g., compatible total salinity and acceptable injectivity) are the apparent factors that determine the use of such waters for injection operations. However, any mixing of incompatible waters without selective removal of scale causing species, particularly sulfate in the forms of sparingly soluble alkaline cations (calcium, strontium, and barium) will result in a wealth of operational problems and difficulties, which in turn, will lead to additional capital and operating costs.
FIG. 2 depicts possible locations of scale deposits throughout the flow paths of water. Scale deposits could take place: (1) at the surface water injection facility where incompatible sources of water are mixed prior to injection; (2) around injection wells where the injected water starts to mix with the reservoir formation water; (3) deep downhole in the reservoir where the injected water displaces reservoir formation water; (4) deep downhole in the reservoir where the converged injected water and formation water are about to reach the range of producing wells; (5) deep downhole in the reservoir where the converged (injected and formation) waters are within the range of producing wells; (6) at the connection of a branched zone where each branch produces different water; (7) at the manifold of a producing zone where water is produced from different blocks within the same producing zone; (8) at topside facility where produced fluids are mixed from different production zones to separate oil and gas from produced waters, or in pipelines that transport produced fluids to on-shore processing facilities; and if applicable (9) at disposal wells where produced water is injected for final disposal.
The first problem is that sulfate scale deposits are hard, adherent, difficult to remove mechanically, and insoluble in mineral acids or other common solvents. Hence, such deposits could cause severe flow restrictions within the drainage radius inside the formation, within the wellbore, and in processing and surface equipment. The visible part of sulfate scale damages, which is the manageable part to some degree, can be seen within the operating equipment and surface processing facilities (e.g., stuck downhole pumps, plugged perforations and tubing strings, choked flowlines, frozen valves, etc.). However, sulfate scale deposits can also be accumulated within the invisible oil-bearing formation, which could cause the ultimate damage (permanent producing wells shut down).
The second problem is that in oil and gas fields, uranium (U-238 and U-235) and thorium (Th-232) are present in immobile chemical forms, whereas radium and its isotopes (their γ-emitting daughter nuclides) can easily be transported with chloride-rich formation waters. Once radium isotopes are leached from their lithological origin, they are no longer supported by their ancestors, and thus they develop their own decay series that refers to Naturally Occurring Radioactive Materials (NORM):Ra-226→Rn-222→Po-218→Pb-214→Bi-214→Po-214→Pb-210→Bi-210→Po-210→stable Pb-206Radium and its isotopes tend to co-precipitate with the sparingly soluble alkaline cations mainly in the forms of sulfate, or carbonate or silicate. As such, formation and produced waters can become radioactive due to the transportation of radium isotopes. External (near any processing equipment), and internal (during maintenance or workovers) radioactive hazards could exist due to NORM adherent to scale during processing. Direct costs of NORM-waste disposal include physical inspection, radionuclide analysis, actual disposal operation, transportation, container decontamination, and storage and decontamination of the removed equipment and pipes. In addition to these direct costs, long-term liability is another potential cost.
The third problem is that radon (Rn-222), the first radioactive decay product of radium, is transported from the reservoir to the surface via the gas phase. Radon can thus be found in the produced natural gas as well as in gas treating facilities (e.g., fractionators and natural gas liquid storage tanks). Due to its high solubility in organic liquids, radon also tends to be concentrated in the liquid phase. If radon is allowed to accumulate and decay (3.8 days half-life), then a serious health threat will exist. This is attributed to α-radiation that results from the decay of the radon short-lived daughter products (polonium: Po-218 and Po-214). In addition, very thin layers of bismuth (Bi-214) and/or lead (Pb-214 and Pb-210) that emit γ-radiation can be formed at the inner surface of gas transport lines as well as gas treating and storage facilities.
The fourth problem is that in downhole, the thermophilic sulfate reducing bacteria converts sulfate to hydrogen sulfide, which leads to reservoir souring. Corrosion of both downhole and surface equipment can result from the production of hydrogen sulfide gas, and hence, sulfide-related workovers must be conducted. Hydrogen sulfide gas is also lethal at levels above 1000 ppm by volume (ppmv) for exposures over two minutes, and therefore, requiring installation of worker-health safeguards monitoring systems. Sour gas ought to be sweetened before it can be sold, and thus gas scrubbing or other treatment systems must be employed.
It is still a common practice unfortunately to use available water in injection operations regardless of the water's contents of scale forming species, and then attempt to correct the problems that occur. Remediation, in particular, of sulfate scale: (1) is very expensive; (2) tends to be a trial-error procedure and field specific (e.g., almost no two identical sets of scale forming conditions exist in any two different fields, and thus any remedial solution can not be generalized); (3) is successful only in less severe cases of scaling; and (4) may cause more problems than they solve under certain conditions (e.g., formation of pseudo scales and extreme emulsion problems).
In such a costly reactive approach, productivity decline due mainly to sulfate scales is accepted as an economic compromise. Rather than extensively stimulating producing wells (backflow, hydraulic fracturing, acid wash, or injection of chemical dissolvers) with long-term remedial costs, and in some cases with irreversible damages (e.g., within the invisible oil-bearing formation), water injection operations should be designed properly from the start, and if not, as typically the case, existed water injection operations ought to be corrected.
The difference in a given oil-gas field economical value with or without proper water injection operations represents the value of injected water. This value could be a liability as with the case of ill-planned water injection operations, or a benefit as with the case of well-planned water injection operations.
The liability of ill-planned water injection can be seen in the following forms: (1) extensive and costly scale remedial workovers; (2) substantial environmental impact and health hazards; (3) reduction in productivity index; (4) deferred oil production; and (5) permanent formation damage and ultimately wells shutdown. In these forms of ill-planned water injection operations, scale costs in the U.S. alone at minimum on the order of $50 billion/year.
The benefits of well-planned water injection, on the other hand, can be seen in the following forms: (1) optimum primary and secondary recovery of hydrocarbons under less severe conditions; (2) minimum formation damages; (3) minimum remedial workovers; and (4) minimum environmental liability and health hazards. As oil-gas reserves are depleted, the current economic environment demands that well-planned water injection be considered as a much-needed “operation” that generates additional revenue, rather than a much-resisted “cost”.
Clearly, the best way to avoid scale problems is to prevent scale from forming. This approach would circumvent the problems incurred with scales build-up, adherence of radioactive species to such scales, radon emission, and reservoir souring by preventing these problems at the onset. This is much more economical than to contend with the damages caused by scale formation problems. This preventive and proactive approach requires some capital expenditures in the near-term time frame, but it will substantially reduce long-term capital and operating costs.
It is apparent that there is a definite need for reliable and efficient methods to remove: (1) sulfate from seawater before injection into formation water; (2) sulfate and/or other scale species from produced waters and/or aquifers waters before mixing with other incompatible streams of saline waters (e.g., seawater and/or reservoir formation water); (3) radon before it decays from natural gas streams; and (4) hydrogen sulfide and other acidic gases from sour natural gas streams and the like. This patent is focused on providing innovative processing methods for solving these problems.